Until an accurate fluid saturation tool is designed, the lack of a solid link between the petrophysical properties of reservoir rock and fluid is a real problem. The reservoir water saturation models are normally based on the standard Archie model to calculate fluid volumes. However, in tight carbonate reservoirs with heterogeneous wettability this model may present unrealistic results for the fluid volume (e.g., water/oil/gas) estimates. An integrated model using resistivity and NMR logs is introduced to quantify the movability of hydrocarbons in the reservoir transition zone. Pay zones may be missed in low-resistivity reservoirs (i.e., transition zones) due to the high water volume estimated from conventional logs. New synthetic resistivity logs are made in both the invaded and non-invaded zones based on assumptions made on the basis of pore and fluid interaction in the NMR log T2 distribution. The differences between the original and synthetic resistivity logs in connection with other log data are dominant signatures of the fluid volumes and movability in the formation. The new approach is developed on basis of exploration well data from a complex and heterogeneous carbonate reservoir in the Norwegian Barents Sea. The estimated fluid movability results are in agreement with the wireline formation tester (WFT) measurements of the well. This model, in addition to the transition zone, can also be applied for hydrocarbon bearing intervals which contain connate water. This approach shows that the reservoir wettability signature can also be identified by comparing the measured and constructed resistivity logs.
Permeability provides an indication of the ability of a porous medium to transmit fluid and is significant in evaluating reservoir productivity. A case study which compares different methods of permeability prediction in a complex carbonate reservoir is presented in this paper. Presence of siliciclastic fines and diagenetic minerals (e.g. dolomitization) within carbonate breccias has resulted in a tight and heterogeneous carbonate reservoir in this case. The first part of this paper covers permeability estimation from independent methods. This part includes conventional core analysis (CCAL), mercury injection capillary pressure tests (MICP), modular formation dynamic tester (MDT), and nuclear magnetic resonance log (NMR). Having different permeability predictors of several methods may be helpful in the permeability calculation, but the deviation of the results from one to the other is often inevitable. Due to discrepancy between the methods it is difficult to select reliable permeability values in the reservoir characterization. In general, the NMR log provides a continuous permeability prediction compared to the other. In the second part of the paper it is attempted to use all the data to calibrate the NMR derived permeability in a realistic behavior. Initially both the Schlumberger Doll Research (SDR) and free-fluid (Timur-Coates) permeability models are employed in this work. The tight and brecciated parts of the rock, wettability effect of the pore surfaces, and residual oil within the flushed zone increase the uncertainty and discrepancy of the NMR estimated permeabilities compared to the other models. A new modified Timur-Coates model was established based on fluid saturations and isolated pore volume of the rock. This model yields a reasonable correlation with core derived permeabilities from CCAL and MICP. However, due to the reservoir heterogeneity particularly in the brecciated parts, a discrepancy of the results between the core data and the created model is not avoidable.
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